Valeura announces second quarter 2016 financial and operating results

CALGARY, Aug. 11, 2016 /CNW/ - Valeura Energy Inc. ("Valeura" or the "Corporation") (TSX: VLE) is pleased to report highlights of its unaudited financial and operating results for the three and six month periods ended June 30, 2016 and an update on subsequent developments including progress towards closing the Statoil farm-in transaction on Valeura's two 100% owned and operated Banarli licences in the Thrace Basin of northwest Turkey. The complete quarterly reporting package for the Corporation, including the unaudited financial statements and associated management's discussion and analysis ("MD&A"), has been filed on SEDAR at and posted on the Corporation's website at

"We expect that the Statoil farm-in at Banarli will be a game-changer for Valeura and we look forward to completing the definitive agreements later this month," said Jim McFarland, President and Chief Executive Officer. "Valeura and Statoil have continued to diligently pursue completion of the farm-in transaction. Following execution of the definitive agreements, the necessary licence interest transfer applications will be submitted to the GDPA for approval, which is a key condition to close the transaction. In parallel, we have continued our operational activities in the shallow formations at Banarli. Progress on the farm-in transaction and operational activities have not been negatively impacted by the recent political developments in Turkey," adds McFarland.

"We also recorded another quarter of solid results in the second quarter of 2016, realizing continued strong natural gas sales price realizations and operating netbacks in Turkey averaging $9.44 per Mcf and $43.06 per boe, respectively, and delivering $2.1 million in funds flow from operations.  Net sales in the second quarter were up 18% from the first quarter of 2016 due to a full quarter of production from the Banarli licences, which contributed 43% to total sales.

"The Statoil farm-in agreement at Banarli has cast a new light on the potential for a basin-centered gas play in the Thrace Basin and we will try to translate that achievement into securing a joint venture partner on certain TBNG JV lands that have similar deep potential. Concurrently, we are eager to get back to work on the shallow formations on the TBNG JV lands to complement the shallow program at Banarli and are exploring various options to enable this," he adds.


  • Executed Letter Agreement with Statoil on May 15, 2016 for farm-in on Banarli Licences
  • Net sales 933 boe/d (43% from Banarli)
  • Funds flow from operations $2.1 million
  • Working capital surplus $5.7 million
  • Natural gas price realization $9.44/Mcf
  • Operating costs $6.23/boe
  • Operating netback $43.02/boe
  • Net capital expenditures $3.2 million

(See below for definitions and advisories)


  • Net petroleum and natural gas sales in Turkey in Q2 2016 averaged 933 barrels of oil equivalent per day ("boe/d"), which was up 18% from Q1 2016 and down 11% from Q2 2015. Net sales in Q2 2016 included 5.6 million cubic feet per day ("MMcf/d") of natural gas and 7.0 barrels of oil per day ("bbl/d").
  • Higher sales in Q2 2016 reflect the impact of a full quarter of sales from Banarli, where sales commenced on March 12, 2016, partially offset by natural declines and minimal capital expenditures on the joint venture lands acquired from Thrace Basin Natural Gas (Turkiye) Corporation ("TBNG") and Pinnacle Turkey Inc. ("PTI") (the "TBNG JV"). Banarli sales in Q2 2016 accounted for 43% of total sales.


Thrace Basin – Banarli Licences (Valeura 100% Working Interest)

Farm-in With Statoil

  • As announced on May 15, 2016, the Corporation's wholly-owned affiliate, Corporate Resources B.V. executed a binding letter agreement (the "Letter Agreement") with Statoil Holding Netherlands B.V. ("Statoil"), a wholly-owned affiliate of Statoil ASA, for a farm-in agreement for the exploration of the deeper formations below approximately 2,500 metres on the Banarli licences targeting a potential basin-centered gas play. On August 2, 2016, Valeura announced that the target date to complete the definitive transaction agreements (the "Definitive Agreements") has been extended to August 19, 2016. The Definitive Agreements are extensive, including a farm-in agreement, a joint operating agreement to apply post-earning and a number of ancillary agreements.
  • Under the terms of the Definitive Agreements, Statoil has the option to earn a 50% participating interest in the deep formations on the Banarli licences by investing in an exploration program that includes payments and carried costs of at least US$36 million. The actual amount invested by Statoil to earn its 50% interest may be higher based on the actual agreed costs of the three-phase work program to satisfy the commitments as described more fully in Valeura's May 15, 2016 press release. The earning work program includes two deep exploration wells and additional 3D seismic.
  • Valeura will operate the deep exploration program during the earning phase under the Definitive Agreements and also continue to operate its 100% retained interest in the shallow formations. Statoil has the option to assume operatorship of the deep program after earning. The Definitive Agreements include provisions for the return of the deep rights licence interests to Valeura in the event Statoil does not earn under the farm-in agreement.
  • Closing of the farm-in transaction is subject to the approval of the General Directorate of Petroleum Affairs ("GDPA") of the Republic of Turkey for the associated upfront transfer of the licence interests. At closing, Statoil is expected to pay Valeura US$6.0 million as a contribution to back costs incurred on the Banarli licences.


Bati Gurgen-1 Well

  • Natural gas sales from the Bati Gurgen-1 well in Q2 2016 averaged 2.4 MMcf/d at an average price realization of $9.31/Mcf, which compares to $9.55/Mcf realized by the TBNG JV in the same period. Banarli gas is being sold to the TBNG JV, net of a transportation and marketing fee.
  • The well is currently producing at a rate of 2.0 MMcf/d. Cumulative production since first gas on March 12, 2016 is approximately 350 MMcf. The gas is being produced from an initial completion of 12 metres of net gas pay in the Osmancik formation at a depth of 1,480 metres. A decision to complete an additional 20 metres of indicated net gas pay in the Osmancik and shallower Danismen formations will await the completion results in the Yayli-1 and Bati Gurgen-2 wells.


Bati Gurgen-2 Well

  • Spudded the Bati Gurgen-2 well on June 19, 2016 and after a sidetrack drilling operation, the sidetrack wellbore was drilled and cased to a true vertical depth of 1,857 metres in the Osmancik formation. Preparations are underway to perforate and test the Osmancik.
  • The initial wellbore at Bati Gurgen-2 was drilled to a true vertical depth of 2,226 metres and penetrated well developed sands in both the Danismen and Osmancik formations but these formations were 25 to 29 metres deeper than expected and the sands appeared to be wet on logs. The sidetrack operation was then carried out targeting the Osmancik formation in a higher structural position and at a bottom-hole location that is approximately 360 metres west of the initial bottom-hole location.


Yayli-1 Well

  • Plugged off the Teslimkoy formation after signing of the Letter Agreement with Statoil and moved up-hole to complete and test 13 metres of indicated net pay in shallower conventional sands in the Osmancik formation at a depth of 1,800 metres. Five intervals were perforated and simultaneously tested yielding initial short term production rates of more than 1.0 MMcf/d but with high associated water production.
  • Production logging indicated that the water production appeared to be sourced primarily from one of the lower perforated intervals but attempts to isolate and plug-off water production and achieve a sustainable gas flow rate were not successful. The well is currently suspended pending an assessment of the option to drill out the bridge plugs and pump the well to handle water production.


Thrace Basin – TBNG JV (Valeura 40% Working Interest)

  • There was no drilling or fracing activity on the TBNG JV lands in Q2 2016.
  • The TBNG JV has continued to seek a farm-in partner to explore the deeper horizons on certain JV lands.



  • The average natural gas price realization in Turkey of $9.44 per Mcf in Q2 2016 was down 6% and 5% from Q1 2016 and Q2 2015, respectively, due primarily to fluctuations in the Turkish Lira exchange rate and the higher proportion of sales from Banarli.
  • The average operating netback of $43.06 per boe in Q2 2016 was down 6% from Q1 2016 and Q2 2015 due to lower natural gas price realizations and higher unit operating costs. (See discussion below regarding non-IFRS measures)
  • The working capital surplus at June 30, 2016 was $5.7 million, including cash of $4.6 million.
  • Funds flow from operations of $2.1 million in Q2 2016 was up marginally from Q1 2016 due to higher volumes partially offset by lower natural gas price realizations and higher general and administrative expenses associated with business development expenses for the Statoil farm-in agreement and other business development projects, and down 29% from Q2 2015 due to lower sales volumes, lower natural gas price realizations, higher unit operating costs and higher general and administrative expenses, partially offset by lower realized foreign exchange losses. (See discussion below regarding non-IFRS measures)
  • Net capital expenditures of $3.2 million in Q2 2016 were up 19% from Q1 2016 due to higher drilling expenditures on the Banarli licences, and down 35% from Q2 2015 due to the lower seismic expenditures on the Banarli licences. Expenditures on the TBNG JV lands were nominal in Q2 2016 and the same period in 2015.
  • Additional financial and operating results are summarized in the Table 1 below.


Table 1 Financial and Operating Results Summary (1)

(thousands of Canadian dollars, except share
and share trading amounts, and as otherwise

Three Months
June 30, 2016

Three Months
March 31, 2016

Six Months
June 30, 2016

Three Months
June 30, 2015

Six Months
June 30, 2015


Petroleum and natural gas revenues






Funds flow from operations (1)






Net loss from operations






Capital expenditures






Net working capital surplus












Common shares outstanding













Share trading





















Crude oil (bbl/d)






Natural Gas (Mcf/d)






boe/d (@ 6:1) (2)






Average reference price

Brent ($ per bbl)






BOTAS Reference ($ per Mcf) (2)






Average realized price

Crude oil ($ per bbl)






Natural gas - Turkey ($ per Mcf)






Average Operating Netback

($ per boe @ 6:1) (1)








The above table includes non-IFRS measures, which may not be comparable to other companies.  Funds flow from operations is calculated as net income (loss) for the period adjusted for non-cash items in the statement of cash flows.  Operating netback is calculated as petroleum and natural gas sales less royalties, production expenses and transportation costs.  See MD&A for further discussion.


Boru Hatlari ile Petrol Tasima Anonim Sirketi ("BOTAS") owns and operates the national crude oil and natural gas pipeline grids in Turkey and purchases the majority of Turkey's natural gas imports.  BOTAS regularly posts prices and its Industrial Interruptible Tariff benchmark is shown herein as a reference price. See the 2015 Annual Information Form for further discussion.



The Corporation is targeting to complete the Definitive Agreements for the Statoil farm-in transaction on the Banarli licences by the end of August 2016, and to subsequently obtain Turkish government approval for the licence interest transfer applications and satisfy certain other conditions precedent as soon as possible. In parallel, Valeura and Statoil are advancing the necessary preparatory work to facilitate spudding the first deep well at Banarli under the farm-in by year-end 2016 targeting a potential basin-centered gas play.

Concurrently, the Corporation expects to continue its strategy to shift emphasis from its non-operated 40% working interest in the TBNG JV to exploration and development drilling in the shallow formations on the Banarli licences in which Valeura retains a 100% interest.

The Corporation currently expects to complete a capital expenditure program in the range of $13 to 15 million (net) in 2016 focused on natural gas development from the shallow formations on the Banarli licences funded from cash on hand and cash flow. The expected payment of US$6.0 million from Statoil at closing of the Banarli farm-in transaction, as a contribution to back costs incurred on the Banarli licences, will provide an important boost to working capital. The work program and budget aims to achieve the following key objectives in 2016:

  • Close the Statoil farm-in on the Banarli licences and spud the Phase 1 deep well (4,000 metres+) by year-end 2016;
  • Seek a joint venture partner to explore the deep formations below approximately 2,500 metres on certain TBNG JV lands, which also have potential for a basin-centered gas play;
  • Pursue other strategic acquisition opportunities;
  • Grow volumes from the shallow formations (less than 2,500 metres depth) on the Banarli licences by drilling up to two additional  conventional gas wells in Q4 2016, following the anticipated closing of the Statoil farm-in agreement, targeting the Osmancik and Danismen formations;
  • Achieve revised corporate average sales volumes in the range of 800 to 900 boe/d (net); and
  • Explore various options to re-start an exploration and development drilling and fracing program on the TBNG JV lands given both conventional natural gas and tight gas potential in formations shallower than 2,500 metres.

(See advisories below regarding outlook disclosures)


Valeura Energy Inc. is a Canada-based public company currently engaged in the exploration, development and production of petroleum and natural gas in Turkey.


When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel ("bbl") of oil or NGLs, or six thousand cubic feet ("Mcf") of natural gas. Barrel of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of 6.0 Mcf to 1.0 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The initial on-stream production rates disclosed in this news release are preliminary in nature and may not be indicative of stabilized on-stream production rates. Initial on-stream production rates are typically disclosed with reference to the number of days in which production is measured (e.g. IP30 refers to an initial on-stream average production rate measured over a 30-day period). Initial on-stream production rates are not necessarily indicative of long-term performance or ultimate recovery. To date, shallow gas conventional wells and fraced unconventional tight gas wells have exhibited relatively high decline rates at more than 50% and 75%, respectively, in their first year of production. All natural gas rates and volumes are presented net of any load fluids.


This news release contains certain forward-looking statements including, but not limited to: the ability to satisfy the conditions for closing pursuant to the Definitive Agreements, including securing GDPA approval for the transfer of the licence interests and the expected timing; the ultimate investment by Statoil under the Definitive Agreements and its ability to earn a 50% interest in the Banarli licences; the anticipated spud date of the Phase 1 well under the Statoil farm-in agreement; the expected US$6.0 million payment from Statoil at the closing of the Statoil farm-in; the Corporation's 2016 work program and budget, operational plans (drilling, completions and workovers), expected capital expenditures and target sales volumes; the results from the Yayli-1 and Bati Gurgen-2 completions in the Osmancik formation; the future completion of additional net pay in the Osmancik and Danismen formations in the Bati Gurgen-1 well and the timing thereof; the planned drilling program on the Banarli licences and the timing thereof; the potential for a basin-centered gas play on the Banarli licences and certain TBNG JV lands; the availability of operating cash flow and the ability to finance development from existing cash and operating cash flow; the ability to grow sales volumes and tie-in new wells and get these on-stream; the timing, estimated costs and ability to fund each of the foregoing; the plans to attract a joint venture partner to explore the deep formations on certain TBNG JV lands; the plan to pursue strategic acquisition opportunities; and the ability to find a viable option to re-start the drilling and fracing program in the shallow formations on the TBNG JV lands. Forward-looking information typically contains statements with words such as "anticipate", estimate", "expect", "target", "potential", "could", "should", "would" or similar words suggesting future outcomes. The Corporation cautions readers and prospective investors in the Corporation's securities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Corporation.

Forward-looking information is based on management's current expectations and assumptions regarding, among other things: political stability of the areas in which the Corporation is operating and completing transactions, and in particular the aftermath of the recent failed coup attempt in Turkey; continued safety of operations and ability to proceed in a timely manner; the ability to reach Definitive Agreements with Statoil and the expected timing; the ability to complete the closing of the Statoil farm-in on the Banarli licences; continued operations of and approvals forthcoming from the GDPA in a manner consistent with past conduct; future seismic, drilling, fracing and re-completion activity on the expected timelines; the prospectivity of the Banarli licences; future production rates and sales volumes, capital efficiencies and associated cash flow; future capital and other expenditures (including the amount and nature thereof); the ability to meet drilling deadlines and other requirements under licences and leases; the ability to attract a partner for deep exploration on certain TBNG JV lands; the ability to successfully pursue strategic acquisition opportunities; the ability to find ways to re-start the drilling and fracing program on the TBNG JV lands; future sources of funding; future economic conditions; future currency and exchange rates; and, the Corporation's continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Corporation's work programs and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, fracing and other specialized oilfield equipment and service providers, changes in the operator's or other partners' plans and unexpected delays and changes in market conditions. Although the Corporation believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

Forward-looking information involves significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a significant degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Corporation including, but not limited to: the risk of not reaching Definitive Agreements with Statoil; the risks of delay and ability to obtain GDPA approval for the Statoil farm-in on the Banarli licences in light of the recent failed coup attempt in Turkey and its aftermath; risks of achieving viable natural gas production rates from the Yayli-1 and Bati Gurgen-2 wells; risks associated with the oil and gas industry (e.g. operational risks in exploration, inherent uncertainties in interpreting geological data, and changes in plans with respect to exploration or capital expenditures, the uncertainty of estimates and projections in relation to costs and expenses, and health, safety, and environmental risks); uncertainty regarding the sustainability of initial production rates and decline rates thereafter, and the ability to mitigate these declines; uncertainty regarding the availability of drilling rigs and equipment and the ability to address technical drilling challenges and manage water production; uncertainty regarding the state of capital markets; uncertainty regarding the amount of operating cash flow and the ability to reduce costs and achieve capital efficiencies; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues, terrorist attacks, insurgencies or civil unrest in Turkey; political stability in Turkey, including potential changes in political leaders or parties or a resurgence of a coup or other political turmoil; the risks of increased costs and delays in timing related to protecting the safety and security of Valeura's personnel and property; the risk of fluctuations in commodity pricing and BOTAS reference prices (denominated in Turkish Lira ("TL")); the risk of fluctuations in foreign exchange rates, particularly the TL; the uncertainty associated with negotiating with third parties in countries other than Canada; the risk of partners having different views on work programs and potential disputes among partners and service providers; the uncertainty regarding government and other approvals; potential changes in laws and regulations; risks associated with weather delays and natural disasters; the risk associated with international activity; and the uncertainty regarding the ability to secure a joint venture partner to pursue deep exploration on certain TBNG JV lands. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.  See Valeura's 2015 AIF for a detailed discussion of the risk factors.

Any financial outlook or future oriented financial information in this news release, as defined by applicable securities legislation, has been approved by management of Valeura. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

Additional information relating to Valeura is also available on SEDAR at

Neither the Toronto Stock Exchange nor its Regulation Services Provider (as that term is defined in the policies of the Toronto Stock Exchange) accepts responsibility for the adequacy or accuracy of this news release.

SOURCE Valeura Energy Inc.

For further information: Jim McFarland, President and CEO, Valeura Energy Inc., (403) 930-1150,; Steve Bjornson, CFO, Valeura Energy Inc., (403) 930-1151,,


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